Bearing blocks for drill bits, drill bit assemblies including bearing blocks and related methods

ABSTRACT

Methods of drilling subterranean formations include coupling at least one bearing block having an initial thickness to a drill bit, engaging a formation with the drill bit within an initial depth of cut range, and reducing the initial thickness of the bearing block by contacting the formation to cause the initial depth of cut range to be at least partially increased. Methods of forming drill bits for drilling subterranean formations include forming at least one rubbing surface of at least one bearing block from at least one material exhibiting a reduced coefficient of friction and coupling the at least one bearing block to the drill bit. Drill bit assemblies include at least one bearing block having a distal portion configured to provide an initial depth of cut range and a base portion configured to provide an increased depth of cut range greater than the initial depth of cut range.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Ser. No. 61/174,412, filed Apr. 30, 2009, the disclosure of which is hereby incorporated herein by this reference in its entirety.

The application is also related to, but does not claim priority to, copending U.S. patent application Ser. No. 11/818,820, filed Jun. 14, 2007, the disclosure of which is hereby incorporated herein by this reference in its entirety.

TECHNICAL FIELD

The present invention, in several embodiments, relates generally to a rotary fixed cutter or “drag” drill bit employing superabrasive cutters for drilling subterranean formations and, more particularly, to use of bearing blocks in association with superabrasive cutters to provide improved accuracy for obtaining one or more target depths of cut for the cutters, a controlled bearing area on the face of the drill bit, or both. Methods of drilling are also encompassed by embodiments of the invention.

BACKGROUND

Rotary drag bits employing superabrasive cutting elements in the form of polycrystalline diamond compact (PDC) cutters have been employed for several decades. PDC cutters are typically comprised of a disc-shaped diamond “table” formed on and bonded under high-pressure and high-temperature conditions to a supporting substrate such as cemented tungsten carbide (WC), although other configurations are known. Bits carrying PDC cutters, which for example, may be brazed into pockets in the bit face, pockets in blades extending from the face, or mounted to studs inserted into the bit body, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. Recent improvements in the design of hydraulic flow regimes about the face of bits, cutter design, and drilling fluid formulation have reduced prior, notable tendencies of such bits to “ball” by increasing the volume of formation material which may be cut before exceeding the ability of the bit and its associated drilling fluid flow to clear the formation cuttings from the bit face.

Even in view of such improvements, however, PDC cutters still suffer from what might simply be termed “overloading” even at low weight-on-bit (WOB) applied to the drill string to which the bit carrying such cutters is mounted, especially if aggressive cutting structures are employed. The relationship of torque to WOB may be employed as an indicator of aggressivity for cutters, so the higher the torque to WOB ratio, the more aggressive the bit. The problem of excessive bit aggressiveness is particularly significant in low compressive strength formations where an unduly great depth of cut (DOC) may be achieved at extremely low WOB. The problem may also be aggravated by drill string bounce or torque and drag, wherein the elasticity of the drill string may cause erratic application of WOB to the drill bit or the drill pipe dragging on the wall of the borehole, with consequent overloading. Moreover, operating PDC cutters at an excessively high DOC may generate more formation cuttings than can be consistently cleared from the bit face and back up the bore hole via the junk slots on the face of the bit by even the aforementioned improved, state-of-the-art bit hydraulics, leading to the aforementioned bit balling phenomenon.

Another, separate problem involves drilling from a zone or stratum of higher formation compressive strength to a “softer” zone of lower compressive strength. As the bit drills into the softer formation without changing the applied WOB (or before the WOB can be reduced by the driller), the penetration of the PDC cutters, and thus the resulting torque on the bit (TOB), increase almost instantaneously and by a substantial magnitude. The abruptly higher torque, in turn, may cause damage to the cutters and/or the bit body itself In directional drilling, such a change causes the tool face orientation of the directional (measuring-while-drilling, or MWD, or a steering tool) assembly to fluctuate, making it more difficult for the directional driller to follow the planned directional path for the bit. Thus, it may be necessary for the directional driller to back off the bit from the bottom of the borehole to reset or reorient the tool face. In addition, a downhole motor, such as drilling fluid-driven Moineau-type motors commonly employed in directional drilling operations in combination with a steerable bottomhole assembly, may completely stall under a sudden torque increase. That is, the bit may stop rotating, thereby stopping the drilling operation and again necessitating backing off the bit from the borehole bottom to re-establish drilling fluid flow and motor output. Such interruptions in the drilling of a well can be time consuming and quite costly.

Numerous attempts using varying approaches have been made over the years to protect the integrity of diamond cutters and their mounting structures and to limit cutter penetration into a formation being drilled. For example, from a period even before the advent of commercial use of PDC cutters, U.S. Pat. No. 3,709,308 discloses the use of trailing, round natural diamonds on the bit body to limit the penetration of cubic diamonds employed to cut a formation. U.S. Pat. No. 4,351,401 discloses the use of surface set natural diamonds at or near the gage of the bit as penetration limiters to control the depth-of-cut of PDC cutters on the bit face. The following other patents disclose the use of a variety of structures immediately trailing PDC cutters (with respect to the intended direction of bit rotation) to protect the cutters or their mounting structures: U.S. Pat. Nos. 4,889,017; 4,991,670; 5,244,039 and 5,303,785. U.S. Pat. No. 5,314,033 discloses, inter alia, the use of cooperating positive and negative or neutral backrake cutters to limit penetration of the positive rake cutters into the formation. Another approach to limiting cutting element penetration is to employ structures or features on the bit body rotationally preceding (rather than trailing) PDC cutters, as disclosed in U.S. Pat. Nos. 3,153,458; 4,554,986; 5,199,511 and 5,595,252.

In another context, that of so-called “anti-whirl” drilling structures, it has been asserted in U.S. Pat. No. 5,402,856 that a bearing surface aligned with a resultant radial force generated by an anti-whirl underreamer should be sized so that force per area applied to the borehole sidewall will not exceed the compressive strength of the formation being underreamed. See also U.S. Pat. Nos. 4,982,802; 5,010,789; 5,042,596; 5,111,892 and 5,131,478.

While some of the foregoing patents recognize the desirability to limit cutter penetration, or DOC, or otherwise limit forces applied to a borehole surface, the disclosed approaches are somewhat generalized in nature and fail to accommodate or implement an engineered approach to achieving a target ROP in combination with more stable, predictable bit performance. Furthermore, the disclosed approaches do not provide a bit or method of drilling which is generally tolerant to being axially loaded with an amount of weight-on-bit over and in excess what would be optimum for the current rate-of-penetration for the particular formation being drilled and which would not generate high amounts of potentially bit-stopping (e.g., stick-slip) or bit-damaging torque-on-bit should the bit nonetheless be subjected to such excessive amounts of weight-on-bit.

Various successful solutions to the problem of excessive cutter penetration are presented in U.S. Pat. Nos. 6,298,930; 6,460,631; 6,779,613 and 6,935,441, the disclosure of each of which is incorporated by reference in its entirety herein. Specifically, U.S. Pat. No. 6,298,930 describes a rotary drag bit including exterior features to control the depth of cut by cutters mounted thereon, so as to control the volume of formation material cut per bit rotation as well as the torque experienced by the bit and an associated bottom-hole assembly. These features, also termed depth of cut control (DOCC) features, provide the bearing surface or sufficient surface area to withstand the axial or longitudinal WOB without exceeding the compressive strength of the formation being drilled and such that the depth of penetration of PDC cutters cutting into the formation is controlled. Because the DOCC features are subject to the applied WOB as well as to contact with the abrasive formation and abrasives-laden drilling fluids, the DOCC features may be layered onto the surface of a steel body bit as an appliqué or hard face weld having the material characteristics required for a high load and high abrasion/erosion environment, or include individual, discrete wear resistant elements or inserts set in bearing surfaces cast in the face of a matrix-type bit, as depicted in FIG. 1 of U.S. Pat. No. 6,298,930. The wear resistant inserts or elements may comprise tungsten carbide bricks or discs, diamond grit, diamond film, natural or synthetic diamond (PDC or TSP), or cubic boron nitride.

FIGS. 10A and 10B of U.S. Pat. No. 6,298,930, respectively, depict different DOCC feature and PDC cutter combinations. In each instance, a single PDC cutter is secured to a combined cutter carrier and DOC limiter, the carrier then being received within a cavity in the face (or on a blade) of a bit and secured therein. The DOC limiter includes a protrusion exhibiting a bearing surface.

The aforementioned and incorporated by reference, U.S. patent application Ser. No. 11/818,820 discloses another solution to the problem of excessive cutter penetration. As described therein, interchangeable bearing blocks may be disposed in receptacles in a bit body of a drill bit proximate to a plurality of PDC cutters. The interchangeable bearing blocks may act to limit the DOC of the PDC cutters proximate to the bearing blocks.

BRIEF SUMMARY

In some embodiments, the present invention includes a method of drilling a subterranean formation comprising coupling at least one bearing block having at least one rubbing surface and an initial thickness to a drill bit, engaging a formation with at least one cutter of the drill bit within an initial depth of cut range, drilling the formation with the drill bit, and reducing the initial thickness of the bearing block by contacting the formation with the at least one rubbing surface to cause the initial depth of cut range to be at least partially increased.

In additional embodiments, the present invention includes a method of drilling a subterranean formation. The method includes coupling at least one bearing block having at least one rubbing surface and an initial thickness to a drill bit, engaging a formation with at least one cutter of the drill bit within an initial depth of cut range, drilling the formation with the drill bit, and increasing the initial depth of cut range by contacting the formation with the at least one rubbing surface to cause the initial thickness of the bearing block to be at least partially reduced. The method may, optionally, also include selecting one or more materials for the bearing block to wear at a predictable rate when engaged with a particular formation material or materials.

In additional embodiments, the present invention includes a method of forming a drill bit for drilling a subterranean formation. The method includes forming at least one bearing block having at least one rubbing surface from at least one material exhibiting at least one of a wear rate and a reduced coefficient of friction as compared to another rubbing surface of the drill bit when the at least one rubbing surface is rotated by the drill bit in contact with the subterranean formation and coupling the at least one bearing block having the at least one rubbing surface to the drill bit.

In further embodiments, the present invention includes a method of drilling comprising drilling a first formation with a first average depth of cut and subsequently drilling a second formation with a second, substantially greater depth of cut.

In yet additional embodiments, the present invention includes a drill bit assembly for subterranean drilling comprising a drill bit including a plurality of blades, a plurality of cutting elements disposed on the plurality of blades, and at least one receptacle located in at least one blade of the plurality of blades. The drill bit assembly further comprises at least one bearing block disposed in the at least one receptacle. The at least one bearing block comprises a distal portion configured to provide at least one cutting element of the plurality of cutting elements with an initial depth of cut range and a base portion configured to provide the at least one cutting element of the plurality of cutting elements with an increased depth of cut range greater than the initial depth of cut range.

In yet additional embodiments, the present invention includes a bearing block for a rotary drill bit for subterranean drilling. The bearing block includes a body portion configured to secure to a complementary structure on a blade of a drill bit and a non-planar rubbing surface configured to contacting a formation during drilling with the drill bit under applied WOB. The bearing block material may be selected for specific wear or frictional characteristics, or both.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a drill bit having an attached bearing block in accordance with a one embodiment of the current invention.

FIG. 2 shows a partial view of the drill bit having the attached bearing block of FIG. 1.

FIG. 3 shows a partial perspective cross-sectional view of the drill bit having a receptacle for receiving the bearing block shown in FIG. 1.

FIG. 4A shows a perspective view of a “peanut-shaped” bearing block in accordance with another embodiment of the current invention.

FIG. 4B shows a front leading view of a keyed bearing block in accordance with yet another embodiment of the current invention.

FIG. 4C shows a side view of a low stress “tooth” bearing block in accordance with yet another embodiment of the current invention.

FIG. 4D shows a side view of a tapered bearing block in accordance with yet another embodiment of the current invention.

FIG. 5A shows a partial cross-sectional view of a receptacle having the peanut-shaped bearing block disposed therein in accordance with yet another embodiment of the current invention.

FIG. 5B shows a partial cross-sectional view of a receptacle having the keyed bearing block disposed therein in accordance with yet another embodiment of the current invention.

FIG. 5C shows a partial cross-sectional view of a “root” receptacle having the tooth bearing block disposed therein in accordance with the fourth embodiment.

FIG. 5D shows a cross-sectional view of a receptacle having the tapered bearing block disposed therein in accordance with yet another embodiment of the current invention.

FIG. 5E shows a cross-sectional view of a receptacle having a concave bearing block disposed therein in accordance with yet another embodiment of the current invention.

FIG. 5F shows a cross-sectional view of a receptacle having a round bearing block disposed therein in accordance with yet another embodiment of the current invention.

FIG. 5G shows a cross-sectional view of a receptacle having a bearing block including an enlarged distal portion disposed therein in accordance with yet another embodiment of the current invention.

FIG. 5H shows a cross-sectional view of a receptacle having a bearing block with a rounded, enlarged distal portion disposed therein in accordance with yet another embodiment of the current invention.

FIG. 6 shows a partial schematic side sectional view illustrating a superimposed cutter profile of the drill bit and bearing block shown in FIG. 1.

DETAILED DESCRIPTION

The illustrations presented herein are not actual views of any particular drilling system, assembly, or device, but are merely idealized representations which are employed to describe embodiments of the present invention.

An embodiment of the current invention is shown in FIGS. 1, 2, 3, and 6. FIG. 1 shows an earth-boring rotary drill bit 10, depicted as a fixed cutter or drag bit employing PDC cutting elements, although of course the invention is not so limited. The bit 10 includes an attached bearing block 40 as viewed by looking upwardly at its face or leading end 12 as if the viewer was positioned at the bottom of a borehole. Bit 10 includes a plurality of PDC cutters 14 bonded by their substrates (diamond tables and substrates not shown separately for clarity), as by brazing, into pockets 16 in blades 18 extending above the face 12 of the bit 10. While the bit 10 depicted in FIG. 1 is a steel body bit, the bit 10 may be fabricated to comprise a particle-matrix composite material. A so-called “infiltration” bit includes a bit body comprising a particle-matrix composite material and is fabricated in a mold using an infiltration process. Recently, pressing and sintering processes have been used to form bit bodies of drill bits and other tools comprising particle-matrix composite materials. Such pressed and sintered bit bodies may be fabricated by pressing (e.g., compacting) and sintering a powder mixture that includes hard particles (e.g., tungsten carbide) and particles of a metal matrix material (e.g., a cobalt-based alloy, an iron-based alloy, or a nickel-based alloy). It should be understood, however, that the invention is not limited to steel body or particle-matrix composite-type bits, and bits of other manufacture may also be configured according to embodiments of the invention and employed with bearing blocks thereof.

Fluid courses 20 lie between blades 18 and are provided with drilling fluid by nozzles 22 secured in nozzle orifices 24, nozzle orifices 24 being at the end of passages leading from a plenum extending into the bit body from a tubular shank at the upper, or trailing, end of the bit 10. Fluid courses 20 extend to junk slots 26 extending upwardly along the side of bit 10 between blades 18. Gage pads (not shown) comprise longitudinally upward extensions of blades 18 and may have wear-resistant inserts or coatings on radially outer surfaces 21 thereof as known in the art. Formation cuttings are swept away from PDC cutters 14 by drilling fluid emanating from nozzle orifices 24 which moves generally radially outwardly through fluid courses 20 and then upwardly through junk slots 26 to an annulus between the drill string from which the bit 10 is suspended and on to the surface.

Simultaneous reference may be made to FIGS. 2 and 3 depicting further details of the bit 10 of FIG. 1. FIG. 2 shows a partial view of the bit 10 exposing the attached bearing block 40. FIG. 3 shows a partial perspective cross-sectional view of the bit 10 having a receptacle 28 for receiving the bearing block 40. The receptacle 28 substantially conforms to a portion of the bearing block 40 for receiving and attaching it therein. Moreover, the receptacle 28 has a defined depth in relation to the cutter pockets 16, and ultimately outer, or cutting, edges of the cutters 14. The defined depth of the receptacle 28 is a function of a desired target depth of cut (TDOC) as discussed below, the thickness of bearing block 40 and the desired positioning of the cutters 14 and size of the cutters 14 in the blade 18 of the bit 10 in order to achieve TDOC as understood by a person of ordinary skill in the art and discussed in the references incorporated herein.

The bearing block 40, as shown in FIGS. 1 and 2 may be billet shaped having a bearing or rubbing surface 32 and an interface surface 34, which in this embodiment includes a rotationally (as the bit is rotated during drilling) leading side 35, a rotationally trailing side 36, a bottom 37, and two ends 38, 39. The interface surface 34 of the bearing block 40 is substantially received within and may be bonded by, for example, brazing, mechanical, or adhesive affixation to the receptacle 28 of the blade 18. The bearing block 40 may also be attached by interference fit or other attachment methods known to one of ordinary skill in the art. When the bearing block 40 is secured to the blade 18 by bonding (including brazing), the bonding material may also act as a filler to fill any interstitial gaps or voids between the perimeter of receptacle 28 and the bearing block 40 to reduce the potential for damage to the bit face 12 along the blade/block interface by abrasives-laden drilling fluids. The receptacle 28 is located, in this embodiment, generally in the cone region 19 of the blade 18, enabling the bearing block 40 to rotationally trail a plurality of cutters 14. The bearing block 40 may be replaced or exchanged with a block having different characteristics, as discussed below. While this embodiment of the invention provides a single bearing block 40 providing a TDOC for associated four cutters 14 on one blade 18, it is recognized that more than one block may be used to advantage on several of the blades for facilitating TDOC for multiple cutters in a given region or regions (cone, nose, etc.) of the bit face 12. Also, it is recognized that the blade 18 may carry multiple blocks thereon.

It is noted that the word “block” as used to describe the bearing block 40 as given in the first embodiment of the invention, or any other embodiment, is not intended to create or import unintended structural limitations. Specifically, the word “block” is intended to mean piece, portion, part, insert, object, or body, without limitation, all of which have mass and shape, without further limitation to material and/or other physical attributes except as expressly presented herein.

The bearing block 40, trailing a plurality of cutters 14, provides a designed bearing or rubbing area 42 affording a surface area specifically tailored to provide support for bit 10 under axial or longitudinal WOB on a selected formation being drilled without exceeding the compressive strength thereof. Further, the bearing block 40 is manufactured, in association with receptacle 28, to provide a precision TDOC relating to the distance (thickness) 44 between the bottom 37 and the rubbing surface 32 of the bearing block 40. Resultantly, the bearing block 40, as inserted into the receptacle 28, defines the TDOC for the plurality of associated cutters 14, the TDOC being indicated in FIG. 2 by the dimension 48 as measured vertically (with respect to the bit face at a given cutter location) between the outermost cutting edges of cutters 14 and rubbing surface 32 of bearing block 40. Accordingly, a bearing block 40 having a selected thickness and, in some embodiments, a selected bearing or rubbing area 42, enables the bearing block 40 to be custom tailored to provide desired drilling characteristics for a bit without alteration or modification to the bit body 10.

Tailoring the configuration of the bearing block advantageously provides specifiable TDOC, limiting manufacturing uncertainty as well as reducing complexity of bit production by bringing to the manufacturing process a high precision and easily alterable component, i.e., the bearing block, without altering the base product, i.e., the bit body or frame. Also, the bearing block may be configured to provide for a selectable rubbing surface area not necessitating alteration to the bit body or frame. Moreover, the bearing block enables a variety of TDOCs and rubbing surface areas to be selectably chosen for a given bit body or frame, reducing inventory loads for bit frames by enhancing design rationalization and further facilitating refurbishment of a given bit in order to acquire a different TDOC and bearing or rubbing surface area by exchanging out and replacing the bearing block. Further, the use of a discrete, separately manufactured bearing block eliminates imprecision associated with hardfacing a steel bit body to provide a DOC limiting feature or complex machining of a bit mold to provide a DOC feature on a matrix bit body face, increasing precision of cutter exposure and desired bearing or rubbing area. Furthermore, the bearing block may be made from or optionally include a facing of an abrasion resistant materials to further enhance the life of the bit

Optionally, as can be seen in FIG. 1, wear-resistant elements or inserts 30, in the form of tungsten carbide bricks or discs (e.g., a circular-shaped bearing block), diamond grit, diamond film, natural or synthetic diamond (polycrystalline diamond compact (PDC) or thermally stable polycrystalline (TSP)), or cubic boron nitride, may be added to the exterior bearing surfaces of the blades 18 or within the rubbing area 42 of the bearing block 40 to reduce the abrasive wear typically encountered by contact with the formation being drilled which is further influenced by WOB as the bit 10 rotates under applied torque. In lieu of inserts, the bearing surfaces or rubbing area may be comprised of, or completely covered with, a wear-resistant material such as a mosaic of tungsten carbide bricks or discs, a layer of diamond grit or a diamond film applied, for example, by chemical vapor deposition.

FIG. 6 shows a partial schematic side sectional view illustrating a superimposed cutter profile 46 in accordance with the first embodiment of the invention. The cutter profile 46 shows the thickness 44 of bearing block 40 which, when disposed in the receptacle 28 of the bit 10, provides a target depth of cut (TDOC) 48 for specific cutters 14. Design criteria for TDOC for a given bit size, profile, cutter number, cutter size and cutter exposure is understood by a person having skill in the art, and, thus, reference may be made to the incorporated references for additional information. Also shown in the cutter profile 46, are optional wear-resistant elements or inserts 30 carried on other blades 18 within the bit cone region 19 (FIG. 1).

Additional embodiments of the invention are shown in FIGS. 4A through 4D and FIGS. 5A through 5H. Turning to FIGS. 4A and 5A, a peanut-shaped bearing block 50 is provided that includes a first rubbing area 52, a second rubbing area 54, a first thickness 56 for first rubbing area 52 and a second thickness 58 for second rubbing area 54. The peanut-shaped bearing block 50 is configured to be received into a complementary socket 60 in a bit blade 62 and brazed 64 thereto. In this embodiment, it is emphasized that the first and second rubbing areas 52, 54, respectively, may each have different shapes and different rubbing areas for contact with a formation during drilling. Also, the first and second thicknesses 56 and 58, respectively, may be different, as illustrated, enabling the bearing block 50 to be designed specifically for a particular application in order to achieve optimal TDOC for different cutters 14 associated with the block 50. In this aspect, the TDOC may be modified for different applications for a given bit frame or bit body by providing a block having the desired thickness or thicknesses without necessitating modification to the bit frame or bit body. It is also recognized that while the bearing block 50 of this embodiment is “peanut-shaped,” as is the complementary socket 60 of a blade 62 (FIG. 5A), that the shape of the bearing block 50 and socket 60 may take on any shape consistent with the capabilities of manufacturing of such structures. Moreover, the peanut-shaped bearing block 50, having different rubbing areas 52, 54 and different thicknesses 56, 58 (and, thus, different TDOCs) may, optionally, provide for a particular or specifiable insertion orientation, as it is to be inserted into the receptacle 60 of the blade 62, beneficially providing an attachment orientation feature for assurance of proper assembly of bearing block 50 with the blade 62. Also, it is recognized that bearing blocks of other shapes may be similarly utilized to advantage.

Turning to FIGS. 4B and 5B, a keyed bearing block 70 includes three different thicknesses 76, 77, and 78 and three different rubbing surfaces 72, 73, and 74, respectively. Generally, the bearing block 70 is “keyed” in the sense of providing two or more thicknesses, each thickness may be associated with one or more adjacent cutters when bearing block 70 is attached to a bit body or frame. Also, the bearing block 70 is “keyed” in that each rubbing surface may exhibit an inclination (tilt) or a complex contour and be specifically tied to the TDOC to be provided a given cutter or cutters, in order to provide a combination of TDOCs within a single bearing block. In the case of an inclined rubbing surface, the angle of inclination may be selected to approximate a helix angle traveled by a cutter as it rotates and travels with the bit at a specific radial location on the bit face when the bit operates at a selected rate of penetration (ROP) or range of ROPs. Accordingly, the bearing block 70 comprises thicknesses 76, 77, 78 having rubbing surface 72 tilted toward its leading side, the rubbing surface 73 that is substantially flat, and the rubbing surface 74 being substantially round or convex, respectively. By providing complex rubbing surface orientations and thicknesses, the cutters (not shown) of a blade 82 will provide highly precise TDOCs, which may also advantageously enable the bearing block 70 to have one or more advantageous contact levels and orientations with the formation being drilled. The bearing block 70 may be secured to the receptacle 80 of the blade 82 by a brazing process 86.

In FIGS. 4C and 5C, a low stress “tooth” bearing block 90 coupled to a “root” receptacle 106 in a blade 100 is shown. In this embodiment, the tooth bearing block 90 may be press-fit into the root receptacle 106. The low stress design includes a smooth, transition free, interface surface between the tooth bearing block 90 and the root receptacle 106, i.e., there are no high stress inflection points. The tooth bearing block 90 includes a thickness 96 and a rubbing surface 92. The tooth bearing block 90 of this embodiment may be structured as a composite comprising a base material 102 made of tungsten matrix having superior loading strength, and a rubbing surface material 104 (i.e., a distal portion) comprising an array or mosaic of thermally stable polycrystalline diamonds, or TSPs, (individual diamond not shown) for superior abrasion resistance.

In FIGS. 4D and 5D, a tapered bearing block 110 is shown. The tapered bearing block 110 may be bonded to a receptacle 112 in a blade 120. The tapered bearing block 110 having a thickness 118 includes a base portion 114 and a rubbing surface 116 (i.e., a distal portion). The base portion 114 may be received within the receptacle 112 while the rubbing surface 116 protrudes from the receptacle 112. The rubbing surface 116 may comprise a substantially frustoconical shape wherein the rubbing surface 116 of the tapered bearing block 110 extends outward to form an enlarged rubbing surface 116 at the distal end of the tapered bearing block 110. The bearing block 110 may be secured to the receptacle 112 of the blade 120 by a braze alloy 118. The enlarged rubbing surface 116 may provide a greater surface area of the rubbing surface 116 or rubbing surfaces of multiple bearing blocks enabling for improved flexibility in the WOB applied to the drill string. As discussed above, designed bearing or rubbing surface areas may be specifically tailored to provide support for a drill bit 10 under axial or longitudinal WOB on a selected formation being drilled without exceeding the compressive strength thereof. For example, a drill bit 10 having a greater rubbing surface area may distribute the load applied by the WOB to a formation being drilled. In some embodiments, as discussed below, the bearing block 110 may be formed from a combination of harder and softer materials. While the bearing blocks 40, 50, 70, 90, 110, 130, 150, 170, and 190 of FIGS. 1, 2, and 4A through 5H are shown as having a variety of shapes (e.g., billet shapes, peanut shapes, elliptical shapes, etc.) the present invention is not so limited as the bearing block may comprise any shape suitable to provide the desired TDOC for a drilling application such as, for example, circular shapes, oval shapes, square shapes, rectangular shapes, etc.

Referring to FIG. 5E, a concave bearing block 130 is shown. The concave bearing block 130 may be bonded by a braze alloy 138 to a receptacle 132 in a blade 140. The concave bearing block 130 may include a base portion 134 partially received within the receptacle 132 and a distal portion 135 including a rubbing surface 136. As discussed in detail below, the bearing block 130 may include a first material forming the distal portion 135 (e.g., the rubbing surface 136) and a second material forming the base portion 134. In some embodiments, the distal portion 135 may be formed from a relatively softer material selected for wear and the base portion 134 may be foamed from a relatively harder material selected for resistance to wear. During operation, a drill bit having the bearing block 130 disposed in the blade 140 of the drill bit may be designed to initially contact a subterranean formation during a drilling process with the distal portion 135 formed from the relatively softer material. The relatively softer material will wear during the operation causing the DOC to increase and exposing the relatively harder material of the base portion 134 disposed proximate to the receptacle 132 in the blade 140 of the drill bit. As the relatively harder material of the base portion 134 is exposed, the amount of wear (i.e., wear rate) of the bearing block 140 will be reduced and the DOC will become substantially constant through the remainder of the drilling process. In other embodiments, the distal portion 135 may be formed from a relatively harder material selected for resistance to wear and the base portion 134 may be formed from a relatively softer material selected for wear.

Referring to FIG. 5F, a bearing block 150 including a rounded (i.e., a convex shape) distal portion 155 including rubbing surface 156 is shown. The bearing block 150 may be bonded by a braze alloy 158 to a receptacle 152 in a blade 160. The bearing block 150 may include a base portion 154 partially received within the receptacle 152. Similar to the bearing block 130 shown and described with reference to FIG. 5E, the bearing block 150 may be formed from a combination of harder and softer materials.

Referring to FIG. 5G, a bearing block 170 including an enlarged distal portion 175 having a rubbing surface 176 is shown. In other words, the distal portion 175 is enlarged relative to a base portion 174 of the bearing block 170. For example, the distal portion 175 may extend laterally outward from a receptacle 172 in a blade 180 in which the bearing block 170 is disposed (i.e., the distal portion 175 extends along an outer surface of the blade 180). Similar to the tapered bearing block 100 shown and described with reference to FIGS. 4D and 5D, the bearing block 170 may provide an enlarged rubbing surface 176 at the distal end of the bearing block 170. The enlarged rubbing surface 176 may provide a greater surface area of the rubbing surface 176 or rubbing surfaces of multiple bearing blocks enabling for improved flexibility in the WOB applied to the drill string. The bearing block 170 may be bonded by a braze alloy 178 to the receptacle 172 in the blade 180. For example, the base portion 174 of the bearing block 170 may be partially received within the receptacle 172. Similar to the bearing block 130 shown and described with reference to FIG. 5E, the bearing block 170 may be formed from a combination of harder and softer materials.

Referring to FIG. 5H, a bearing block 190 including a rounded (i.e., a convex shape), enlarged distal portion 195 having a rubbing surface 196 is shown. In other words, the distal portion 175 is enlarged relative to a base portion 194 of the bearing block 190. Similar to the tapered bearing block 100 shown and described with reference to FIGS. 4D and 5D, the bearing block 190 may provide an enlarged rubbing surface 196 at the distal end of the bearing block 190. The enlarged rubbing surface 196 may provide a greater surface area of the rubbing surface 196 or rubbing surfaces of multiple bearing blocks enabling for improved flexibility in the WOB applied to the drill string. The bearing block 190 may be bonded by a braze alloy 198 to a receptacle 192 in a blade 200. For example, the base portion 194 of the bearing block 190 may be partially received within the receptacle 192. Similar to the bearing block 130 shown and described with reference to FIG. 5E, the bearing block 190 may be formed from a combination of harder and softer materials.

In some embodiments, the bearing block may comprise a “harder” material exhibiting high hardness and wear-resistant properties such as abrasion- and erosion-resistant characteristics. So-called “harder” materials may comprise materials such as tungsten carbide, natural or synthetic diamond (polycrystalline diamond compact (PDC) or thermally stable polycrystalline (TSP)), ceramic materials, or impregnated materials composed of diamond material, such as natural or synthetic diamond grit, dispersed within a matrix of wear resistant material. Use of harder materials in the bearing block may allow for a relatively consistent DOC during a drilling operation through one or more formations. That is, the harder, wear-resistant bearing block will substantially maintain its thickness throughout the drilling operation. Thus, an initially TDOC specified will be substantially maintained during a drilling operation. Other materials may also be utilized, alone or in combination, for the bearing block including homogenous or heterogeneous block materials. For example, materials exhibiting high hardness and abrasion- and erosion-resistant characteristics may be carried on supporting substrates exhibiting superior toughness and ductility such as thermally stable polycrystalline (TSP) diamond material disposed on a supporting substrate and other carbide materials.

In some embodiments, low friction materials (i.e., materials exhibiting a lower frictional force when the bearing block is rotated in contact with the formation) such as, for example, diamond, ceramic, hardened steel, or other alloy materials, or materials having a polished or other low-friction surface or coating may be selected. Low friction materials may exhibit a relatively lower coefficient of friction between the rubbing surface of the bearing block and the formation as the rubbing surface travels across the formation, resulting in a decrease in the amount of frictional force. For example, referring to FIG. 2, a portion of the bearing block 40 (e.g., the rubbing surface 32) may be formed from a material having a dynamic coefficient of friction of 0.2 or lower. Such a bearing block may exhibit a reduced coefficient of friction between the rubbing surface of the bearing block and the formation as the rubbing surface travels across the formation as compared to another rubbing surface of the drill bit (i.e., another surface of the drill bit that contacts the formation during a drilling process). For example, a rubbing surface of a portion of the bit body of the drill bit (e.g., the blades 18 of the drill bit 10) may exhibit a dynamic coefficient of friction of 0.25 or greater between a rubbing surface of the bit body (e.g., an outer portion of the blades 18) and the formation as the rubbing surface of the bit body travels across the formation (e.g., a limestone formation). A bearing block exhibiting a reduced coefficient of friction as compared to another rubbing surface of the drill bit (e.g., less than 0.25) may allow for reduced torque in the drill string as the rubbing surface of the bearing block travels across the formation. As discussed above, increasing the WOB increases the forces between the bearing block and the cutting elements increase and also increases the amount of torque required to turn the drill string. Therefore, providing a bearing block with a rubbing surface exhibiting a lower coefficient between the rubbing surface and the formation will allow for reduced torque in a drill operation under a given amount of WOB. Further, reduced friction reduces the amount of torque required to rotate the drill bit, which may be significant in directional drilling using downhole motors wherein the torque output is limited.

Further, in some embodiments it may be desirable to form a bearing block from a “softer” material, for example, a material selected for wear and exhibiting diminished properties such as wear-resistance, hardness, and abrasion- and erosion-resistant characteristics as compared to those detailed above. So-called “softer” materials may comprise materials such as a relatively soft carbide material, steel, other alloy, or particle-matrix composite materials. For example, a relatively soft carbide material may comprise hard particles (e.g., tungsten carbide) in a metal matrix material such as, for example, a cobalt or cobalt-based alloy. Such a relatively soft carbide may include a higher percentage by weight of the metal matrix material causing the resultant carbide to exhibit a relatively lower amount of wear-resistance than a carbide having a lower percentage by weight of the metal matrix material. For example, a relatively soft carbide may include a cobalt or cobalt-based alloy content of 4% to 30% by weight. In some embodiments, the relatively soft carbide may include a cobalt or cobalt-based alloy content of 16% by weight.

As above, the softer material may be used to form the entire bearing block or to form the rubbing surface while another material is used to form the base portion. The softer material may enable the thickness of the bearing block to be varied during a drilling process without having to modify the drill bit. For example, a drilling process may begin with a bearing block of an initial thickness providing for a lower TDOC. As the drilling process progresses the softer material of the bearing block will be subject to abrasion and erosion exhibited in the drilling process. The abrasion and erosion may tend to reduce the thickness of the bearing block with diminished wear-resistance. As the thickness of the bearing block is reduced, the DOC will increase. Thus, the bearing block formed from a softer material may enable drilling operations to select a variable TDOC based on wellbore variables such as the type and depth of the formations being drilled with the bit, and the material properties of the softer material.

For example, the bearing block may be fabricated to provide a variable DOCC and TDOC during a directional drilling operation. In a directional drilling operation, the bottomhole assembly of a drill string including a downhole motor such as a Positive Displacement Motor (PDM) or hydraulic Moineau-type may be directed to follow a desired path. Systems utilizing ribs or a bent sub to steer a drill string are disclosed, for example, in U.S. Pat. No. 7,413,032, issued Aug. 19, 2008, entitled “Self-controlled Directional Drilling Systems and Methods” and U.S. Pat. No. 5,738,178, issued Apr. 14, 1998, entitled “Method and Apparatus for Navigational Drilling with a Downhole Motor Employing Independent Drill String and Bottomhole Assembly Rotary Orientation and Rotation” both of which are assigned to the assignee of the present invention and the entire disclosure of each of which patents is incorporated herein by this reference. In a directional drilling process, the initial bearing block thickness may be selected to exhibit an initial, relatively low TDOC allowing for better tool face control as a curve to drill directionally is initiated. As the curve is “kicked off” and the drill string is directed at an angle to the original substantially vertical drilling direction, the bearing block comprising a softer material will exhibit a reduced thickness and provide an increased DOC for drilling the curve and the subsequent lateral (tangent) section of the wellbore in a more aggressive manner. As the drill string is directed in a substantially horizontal direction, the thickness of the bearing block may be even further reduced allowing for an ever greater DOC.

In another scenario, it is contemplated that a first formation requiring a lesser TDOC for an optimum rate of penetration (ROP) may be drilled through initially, followed by drilling through a second formation requiring a greater TDOC for an optimum rate of penetration. Based upon the material characteristics of a portion of the bearing block to be worn during drilling, the formation abrasivity, erosiveness of the drilling fluid employed, and the thickness of the first formation to be drilled through before reaching the second formation, the bearing block wear material and thickness of such material may be selected to substantially optimize drilling performance in both formations. Thus, an embodiment of a method of drilling according to the present invention comprises drilling a first formation with a first average depth of cut and subsequently drilling a second formation with a second, substantially greater depth of cut.

Referring again to FIGS. 5A through 5H, it is also contemplated by the current invention that the bearing blocks 50, 70, 90, 110, 130, 150, 170, and 190 may comprise a combination of harder and softer materials. For example, with reference to FIGS. 4B and 5B, the bearing block 70 may comprise a first rubbing surface 72 formed from a softer material, as discussed above. The bearing block may also comprise a rubbing surface 74 comprising a harder material, as also discussed above. In operation, the thickness 76 of the bearing block 70 may provide an initial DOC. However, as the thickness 76 of the softer rubbing surface is reduced, the DOC will increase until the thickness 78 of the harder rubbing surface 72 is equal to or greater than that of the thickness 76 of the softer rubbing surface 74. Similarly, as shown in FIG. 5E, for example, the rubbing surface 136 of the bearing block 130 may comprise a softer material, as described above. The base portion 134 may comprise a harder material, as also discussed above. In operation, the rubbing surface 136 of the bearing block 130 may provide an initial DOC. However, as the rubbing surface 136 is reduced, the DOC will increase until the base portion 134 is exposed. Thus, exposing a distal surface of the base portion 134 formed from a harder material may be utilized to provide a harder rubbing surface 137. It is also noted that, as above, the harder material may be disposed in the initial rubbing surface and the softer material may be disposed below the harder layer. For example, the bearing block 130 shown in FIG. 5E, may comprise a rubbing surface 136 comprising a harder material such as a harder carbide and a base portion 134 comprising a softer material such as a relatively soft carbide.

In summary, a bearing block according to embodiments of the invention may be configured for use with one or more blades of a bit body or frame. The inventive bearing block is designed so that it may be replaced or repaired, typically, without necessitating alteration to a standardized bit frame. The interchangeable, customizable bearing block may include one or more of a specifically selected thickness, a rubbing surface orientation and an area suitable for improving drilling performance of a bit. Bearing blocks with varying thicknesses and rubbing surface orientations, topographies and areas may be implemented. Use of different surface orientations and, particular, shapes may be used to create more or less rubbing at certain speeds (DOC) or at different wear states. This variability may be enhanced by utilizing a bearing block that exhibits a rubbing surface area contacting the formation that changes with wear.

The bearing block may be located substantially in the cone region on a blade of the bit frame, in the cone/nose region, in the nose region, etc. The interchangeable, modifiable bearing block according to embodiments of the invention brings manufacturing selectability by providing a customizable product suitable for use with a common bit frame, thus, not requiring a complex assortment of stocked bit frames. Each bearing block is selectably insertable into a bit frame, enabling a bit to be customized or adapted for different drilling applications, including difficult formations, or for different drilling systems. Also, by providing a block that is selectively connectable to a bit frame, different cutting characteristics may be advantageously obtained without affecting or requiring alteration of the bit frame. Moreover, the bearing block may be designed for specific associated cutters or sets of cutters to obtain customized cutter profiles and TDOCs, due to the ability of the bearing block with a customized profile and wear properties to be connected to a common bit frame without alteration thereto.

Additionally, bearing blocks fabricated from a variety of materials may provide greater flexibility in drilling operations utilizing bearing blocks for varied drilling applications. Materials such as harder materials may be selected to provide a substantially consistent DOC through a drilling process. Alternatively, softer materials may be selected to provide a varied depth of cut during a drilling process. Bearing blocks comprising different combinations of materials may enable for even greater flexibility in varying the DOC and DOCC throughout a drilling process. Further, lower friction materials may also be selected to increase efficiency during the drilling process.

While particular embodiments of the invention have been shown and described, numerous variations and alternate embodiments will occur to those skilled in the art. Accordingly, it is intended that the invention only be limited in terms of the appended claims and their legal equivalents. 

1. A method of drilling a subterranean formation, the method comprising: coupling at least one bearing block having at least one rubbing surface and an initial thickness to a drill bit; engaging a formation with at least one cutter of the drill bit within an initial depth of cut range; drilling the formation with the drill bit; and reducing the initial thickness of the bearing block by contacting the formation with the at least one rubbing surface to cause the initial depth of cut range to be at least partially increased.
 2. The method of claim 1, further comprising forming the at least one bearing block at least partially from a material selected for wear.
 3. The method of claim 2, wherein forming the at least one bearing block at least partially from a material selected for wear comprises forming the at least one bearing block at least partially from at least one of a relatively soft carbide material, a steel material, an alloy material, and a particle-matrix composite material.
 4. The method of claim 1, further comprising forming the at least one bearing block from a first material selected for wear and a second material selected to exhibit a wear resistance greater than the first material.
 5. The method of claim 4, wherein forming the at least one bearing block from a first material selected for wear and a second material selected to exhibit a wear resistance greater than the first material comprises forming a rubbing surface of the at least one bearing block with the first material and forming a base portion of the at least one bearing block with the second material.
 6. The method of claim 4, wherein forming the at least one bearing block from a first material selected for wear and a second material selected to exhibit a wear resistance greater than the first material comprises forming a rubbing surface of the at least one bearing block with the second material and forming a base portion of the at least one bearing block with the first material.
 7. The method of claim 4, wherein forming the at least one bearing block from a first material selected for wear and a second material selected to exhibit a wear resistance greater than the first material comprises: selecting the first material from at least one of a relatively soft carbide material, a steel material, a metal alloy material, and a particle-matrix composite material; and selecting the second material from at least one of a diamond material, a thermally stable polycrystalline material, a ceramic material, and a tungsten carbide material.
 8. The method of claim 1, wherein drilling the formation with the drill bit comprises drilling a first formation using the drill bit with a first average depth of cut and further comprising drilling a second, subsequent formation using the drill bit with a second, substantially greater average depth of cut.
 9. A method of forming a drill bit for drilling a subterranean formation, the method comprising: forming at least one rubbing surface of at least one bearing block from at least one material exhibiting a reduced coefficient of friction as compared to another rubbing surface of the drill bit when the at least one rubbing surface is rotated by the drill bit in contact with the subterranean formation; and coupling the at least one bearing block having the at least one rubbing surface to the drill bit.
 10. The method of claim 9, wherein forming at least one rubbing surface of at least one bearing block from at least one material exhibiting a reduced coefficient of friction comprises selecting the at least one material from at least one of a diamond material, a ceramic material, a hardened steel material, an alloy material, and a material having a polished surface.
 11. The method of claim 9, wherein forming at least one rubbing surface of at least one bearing block from at least one material exhibiting a reduced coefficient of friction comprises selecting the at least one material to exhibit a coefficient of friction of less than 0.2.
 12. A drill bit assembly for subterranean drilling, comprising: a drill bit comprising a plurality of blades, a plurality of cutting elements disposed on the plurality of blades, and at least one receptacle located in at least one blade of the plurality of blades; and at least one bearing block disposed in the at least one receptacle, the at least one bearing block comprising: a distal portion configured to provide at least one cutting element of the plurality of cutting elements with an initial depth of cut range; and a base portion configured to provide the at least one cutting element of the plurality of cutting elements with an increased depth of cut range greater than the initial depth of cut range.
 13. The drill bit assembly for subterranean drilling of claim 12, wherein the at least one bearing block further comprises at least one of a tapered shape and a concave shape.
 14. The drill bit assembly for subterranean drilling of claim 12, wherein the distal portion of the at least one bearing block extends laterally outward from the base portion of the at least one bearing block.
 15. The drill bit assembly for subterranean drilling of claim 14, wherein the distal portion of the at least one bearing block comprises a convex shape.
 16. The drill bit assembly for subterranean drilling of claim 12, wherein the distal portion of the at least one bearing block comprises a first material selected for wear and the base portion of the at least one bearing block comprises a second material exhibiting a wear resistance greater than the first material.
 17. The drill bit assembly for subterranean drilling of claim 16, wherein the distal portion of the at least one bearing block comprises at least one of a relatively soft carbide material, a steel material, an alloy material, and a particle-matrix composite material and the base portion of the at least one bearing block comprises at least one of a diamond material, a thermally stable polycrystalline material, a ceramic material, and a tungsten carbide material.
 18. The drill bit assembly for subterranean drilling of claim 12, wherein the distal portion of the at least one bearing block comprises a first material comprising a wear resistant material and the base portion of the at least one bearing block comprises a second material exhibiting a wear resistance less than the first material.
 19. The drill bit assembly for subterranean drilling of claim 18, wherein the distal portion of the at least one bearing block comprises at least one of a diamond material, a thermally stable polycrystalline material, a ceramic material, and a tungsten carbide material and the base portion of the at least one bearing block comprises at least one of a relatively soft carbide material, a steel material, an alloy material, and a particle-matrix composite material.
 20. The drill bit assembly for subterranean drilling of claim 12, wherein at least one of the distal portion of the at least one bearing block and the base portion of the at least one bearing block comprise a material exhibiting a coefficient of friction between 0.01 and 0.20. 